Enhanced hydrocarbon recovery by convective heating of oil sand formations

ABSTRACT

The present invention involves a method and apparatus for enhanced recovery of petroleum fluids from the subsurface by convective heating of the oil sand formation and the heavy oil and bitumen in situ by a downhole electric heater. Multiple propped vertical hydraulic fractures are constructed from the well bore into the oil sand formation and filled with a diluent. The heater and downhole pump force thermal convective flow of the heated diluent to flow upward and outward into the propped fractures and circulating back down and back towards the well bore heating the oil sands and in situ bitumen on the vertical faces of the propped fractures. The diluent now mixed with produced products from the oil sand re-enters the bottom of the well bore and passes over the heater element and is reheated to continue to flow in the convective cell. Thus the heating and diluting of the in place bitumen occurs predominantly circumferentially, i.e. orthogonal to the propped fracture, by diffusion from the propped vertical fracture faces progressing at a nearly uniform rate into the oil sand deposit. In situ hydrogenation and thermal cracking of the in place bitumen can provide a higher grade produced product. The heated low viscosity oil is produced through the well bore at the completion of the active heating phase of the process.

RELATED APPLICATION

This application is a continuation-in-part of copending U.S. patentapplication Ser. No. 11/363,540, filed Feb. 27, 2006, U.S. patentapplication Ser. No. 11/277,308, filed Mar. 27, 2006, U.S. patentapplication Ser. No. 11/277,775, filed Mar. 29, 2006, U.S. patentapplication Ser. No. 11/277,815, filed Mar. 29, 2006, U.S. patentapplication Ser. No. 11/277,789, filed Mar. 29, 2006, U.S. patentapplication Ser. No. 11/278,470, filed Apr. 3, 2006, and U.S. patentapplication Ser. No. 11/379,123, filed Apr. 18, 2006.

TECHNICAL FIELD

The present invention generally relates to enhanced recovery ofpetroleum fluids from the subsurface by convective heating of the oilsand formation and the viscous heavy oil and bitumen in situ, moreparticularly to a method and apparatus to extract a particular fractionof the in situ hydrocarbon reserve by controlling the reservoirtemperature and pressure, while also minimizing water inflow into theheated zone and well bore, resulting in increased production ofpetroleum fluids from the subsurface formation.

BACKGROUND OF THE INVENTION

Heavy oil and bitumen oil sands are abundant in reservoirs in many partsof the world such as those in Alberta, Canada, Utah and California inthe United States, the Orinoco Belt of Venezuela, Indonesia, China andRussia. The hydrocarbon reserves of the oil sand deposit is extremelylarge in the trillions of barrels, with recoverable reserves estimatedby current technology in the 300 billion barrels for Alberta, Canada anda similar recoverable reserve for Venezuela. These vast heavy oil(defined as the liquid petroleum resource of less than 20° API gravity)deposits are found largely in unconsolidated sandstones, being highporosity permeable cohesionless sands with minimal grain to graincementation. The hydrocarbons are extracted from the oils sands eitherby mining or in situ methods.

The heavy oil and bitumen in the oil sand deposits have high viscosityat reservoir temperatures and pressures. While some distinctions havearisen between tar and oil sands, bitumen and heavy oil, these termswill be used interchangeably herein. The oil sand deposits in Alberta,Canada extend over many square miles and vary in thickness up tohundreds of feet thick. Although some of these deposits lie close to thesurface and are suitable for surface mining, the majority of thedeposits are at depth ranging from a shallow depth of 150 feet down toseveral thousands of feet below ground surface. The oil sands located atthese depths constitute some of the world's largest presently knownpetroleum deposits. The oil sands contain a viscous hydrocarbonmaterial, commonly referred to as bitumen, in an amount that ranges upto 15% by weight. Bitumen is effectively immobile at typical reservoirtemperatures. For example at 15° C., bitumen has a viscosity of˜1,000,000 centipoise. However, at elevated temperatures the bitumenviscosity changes considerably to ˜350 centipoise at 100° C. down to ˜10centipoise at 180° C. The oil sand deposits have an inherently highpermeability ranging from ˜1 to 10 Darcy, thus upon heating, the heavyoil becomes mobile and can easily drain from the deposit.

Solvents applied to the bitumen soften the bitumen and reduce itsviscosity and provide a non-thermal mechanism to improve the bitumenmobility. Hydrocarbon solvents consist of vaporized light hydrocarbonssuch as ethane, propane, or butane or liquid solvents such as pipelinediluents, natural condensate streams, or fractions of synthetic crudes.The diluent can be added to steam and flashed to a vapor state or bemaintained as a liquid at elevated temperature and pressure, dependingon the particular diluent composition. While in contact with thebitumen, the saturated solvent vapor dissolves into the bitumen. Thisdiffusion process is due to the partial pressure difference between thesaturated solvent vapor and the bitumen. As a result of the diffusion ofthe solvent into the bitumen, the oil in the bitumen becomes diluted andmobile and will flow under gravity. The resultant mobile oil may bedeasphalted by the condensed solvent, leaving the heavy asphaltenesbehind within the oil sand pore space with little loss of inherent fluidmobility in the oil sands due to the small weight percent (5-15%) of theasphaltene fraction to the original oil in place. Deasphalting the oilfrom the oil sands produces a high grade quality product by 3°-5° APIgravity. If the reservoir temperature is elevated the diffusion rate ofthe solvent into the bitumen is raised considerably being two orders ofmagnitude greater at 100° C. compared to ambient reservoir temperaturesof ˜15° C.

In situ methods of hydrocarbon extraction from the oil sands consist ofcold production, in which the less viscous petroleum fluids areextracted from vertical and horizontal wells with sand exclusionscreens, CHOPS (cold heavy oil production system) cold production withsand extraction from vertical and horizontal wells with large diameterperforations thus encouraging sand to flow into the well bore, CSS(cyclic steam stimulation) a huff and puff cyclic steam injection systemwith gravity drainage of heated petroleum fluids using vertical andhorizontal wells, stream flood using injector wells for steam injectionand producer wells on 5 and 9 point layout for vertical wells andcombinations of vertical and horizontal wells, SAGD (steam assistedgravity drainage) steam injection and gravity production of heatedhydrocarbons using two horizontal wells, VAPEX (vapor assisted petroleumextraction) solvent vapor injection and gravity production of dilutedhydrocarbons using horizontal wells, and combinations of these methods.

Cyclic steam stimulation and steam flood hydrocarbon enhanced recoverymethods have been utilized worldwide, beginning in 1956 with thediscovery of CSS, huff and puff or steam-soak in Mene Grande field inVenezuela and for steam flood in the early 1960s in the Kern River fieldin California. These steam assisted hydrocarbon recovery methodsincluding a combination of steam and solvent are described, see U.S.Pat. No. 3,739,852 to Woods et al, U.S. Pat. No. 4,280,559 to Best, U.S.Pat. No. 4,519,454 to McMillen, U.S. Pat. No. 4,697,642 to Vogel, andU.S. Pat. No. 6,708,759 to Leaute et al. The CSS process raises thesteam injection pressure above the formation fracturing pressure tocreate fractures within the formation and enhance the surface areaaccess of the steam to the bitumen. Successive steam injection cyclesreenter earlier created fractures and thus the process becomes lessefficient over time. CSS is generally practiced in vertical wells, butsystems are operational in horizontal wells, but have complications dueto localized fracturing and steam entry and the lack of steam flowcontrol along the long length of the horizontal well bore.

Descriptions of the SAGD process and modifications are described, seeU.S. Pat. No. 4,344,485 to Butler, and U.S. Pat. No. 5,215,146 toSanchez and thermal extraction methods in U.S. Pat. No. 4,085,803 toButler, U.S. Pat. No. 4,099,570 to Vandergrift, and U.S. Pat. No.4,116,275 to Butler et al. The SAGD process consists of two horizontalwells at the bottom of the hydrocarbon formation, with the injector welllocated approximately 10-15 feet vertically above the producer well. Thesteam injection pressures exceed the formation fracturing pressure inorder to establish connection between the two wells and develop a steamchamber in the oil sand formation. Similar to CSS, the SAGD method hascomplications, albeit less severe than CSS, due to the lack of steamflow control along the long section of the horizontal well and thedifficulty of controlling the growth of the steam chamber.

A thermal steam extraction process referred to a HASDrive (heatedannulus steam drive) and modifications thereof are described to heat andhydrogenate the heavy oils in situ in the presence of a metal catalyst,see U.S. Pat. No. 3,994,340 to Anderson et al, U.S. Pat. No. 4,696,345to Hsueh, U.S. Pat. No. 4,706,751 to Gondouin, U.S. Pat. No. 5,054,551to Duerksen, and U.S. Pat. No. 5,145,003 to Duerksen. It is disclosedthat at elevated temperature and pressure the injection of hydrogen or acombination of hydrogen and carbon monoxide to the heavy oil in situ inthe presence of a metal catalyst will hydrogenate and thermal crack atleast a portion of the petroleum in the formation.

Thermal recovery processes using steam require large amounts of energyto produce the steam, using either natural gas or heavy fractions ofproduced synthetic crude. Burning these fuels generates significantquantities of greenhouse gases, such as carbon dioxide. Also, the steamprocess uses considerable quantities of water, which even though may bereprocessed, involves recycling costs and energy use. Therefore a lessenergy intensive oil recovery process is desirable.

Solvent assisted recovery of hydrocarbons in continuous and cyclic modesare described including the VAPEX process and combinations of steam andsolvent plus heat, see U.S. Pat. No. 4,450,913 to Allen et al, U.S. Pat.No. 4,513,819 to Islip et al, U.S. Pat. No. 5,407,009 to Butler et al,U.S. Pat. No. 5,607,016 to Butler, U.S. Pat. No. 5,899,274 to Frauenfeldet al, U.S. Pat. No. 6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Limet al, and U.S. Pat. No. 6,883,607 to Nenniger et al. The VAPEX processgenerally consists of two horizontal wells in a similar configuration toSAGD; however, there are variations to this including spaced horizontalwells and a combination of horizontal and vertical wells. The startupphase for the VAPEX process can be lengthy and take many months todevelop a controlled connection between the two wells and avoidpremature short circuiting between the injector and producer. The VAPEXprocess with horizontal wells has similar issues to CSS and SAGD inhorizontal wells, due to the lack of solvent flow control along the longhorizontal well bore, which can lead to non-uniformity of the vaporchamber development and growth along the horizontal well bore.

Direct heating and electrical heating methods for enhanced recovery ofhydrocarbons from oil sands have been disclosed in combination withsteam, hydrogen, catalysts and/or solvent injection at temperatures toensure the petroleum fluids gravity drain from the formation and atsignificantly higher temperatures (300° to 400° range and above) topyrolysis the oil sands. See U.S. Pat. No. 2,780,450 to Ljungström, U.S.Pat. No. 4,597,441 to Ware et al, U.S. Pat. No. 4,926,941 to Glandt etal, U.S. Pat. No. 5,046,559 to Glandt, U.S. Pat. No. 5,060,726 to Glandtet al, U.S. Pat. No. 5,297,626 to Vinegar et al, U.S. Pat. No. 5,392,854to Vinegar et al, and U.S. Pat. No. 6,722,431 to Karanikas et al. Insitu combustion processes have also been disclosed see U.S. Pat. No.5,211,230 to Ostapovich et al, U.S. Pat. No. 5,339,897 to Leaute, U.S.Pat. No. 5,413,224 to Laali, and U.S. Pat. No. 5,954,946 to Klazinga etal.

In situ processes involving downhole heaters are described in U.S. Pat.No. 2,634,961 to Ljungström, U.S. Pat. No. 2,732,195 to Ljungström, U.S.Pat. No. 2,780,450 to Ljungström. Electrical heaters are described forheating viscous oils in the forms of downhole heaters and electricalheating of tubing and/or casing, see U.S. Pat. No. 2,548,360 to Germain,U.S. Pat. No. 4,716,960 to Eastlund et al, U.S. Pat. No. 5,060,287 toVan Egmond, U.S. Pat. No. 5,065,818 to Van Egmond, U.S. Pat. No.6,023,554 to Vinegar and U.S. Pat. No. 6,360,819 to Vinegar. Flamelessdownhole combustor heaters are described, see U.S. Pat. No. 5,255,742 toMikus, U.S. Pat. No. 5,404,952 to Vinegar et al, U.S. Pat. No. 5,862,858to Wellington et al, and U.S. Pat. No. 5,899,269 to Wellington et al.Surface fired heaters or surface burners may be used to heat a heattransferring fluid pumped downhole to heat the formation as described inU.S. Pat. Patent No. 6,056,057 to Vinegar et al and U.S. Pat. No.6,079,499 to Mikus et al.

The thermal and solvent methods of enhanced oil recovery from oil sands,all suffer from a lack of surface area access to the in place bitumen.Thus the reasons for raising steam pressures above the fracturingpressure in CSS and during steam chamber development in SAGD, are toincrease surface area of the steam with the in place bitumen. Similarlythe VAPEX process is limited by the available surface area to the inplace bitumen, because the diffusion process at this contact controlsthe rate of softening of the bitumen. Likewise during steam chambergrowth in the SAGD process the contact surface area with the in placebitumen is virtually a constant, thus limiting the rate of heating ofthe bitumen. Therefore both methods (heat and solvent) or a combinationthereof would greatly benefit from a substantial increase in contactsurface area with the in place bitumen. Hydraulic fracturing of lowpermeable reservoirs has been used to increase the efficiency of suchprocesses and CSS methods involving fracturing are described in U.S.Pat. No. 3,739,852 to Woods et al, U.S. Pat. No. 5,297,626 to Vinegar etal, and U.S. Pat. No. 5,392,854 to Vinegar et al. Also during initiationof the SAGD process over pressurized conditions are usually imposed toaccelerated the steam chamber development, followed by a prolongedperiod of under pressurized condition to reduce the steam to oil ratio.Maintaining reservoir pressure during heating of the oil sands has thesignificant benefit of minimizing water inflow to the heated zone and tothe well bore.

Hydraulic fracturing of petroleum recovery wells enhances the extractionof fluids from low permeable formations due to the high permeability ofthe induced fracture and the size and extent of the fracture. A singlehydraulic fracture from a well bore results in increased yield ofextracted fluids from the formation. Hydraulic fracturing of highlypermeable unconsolidated formations has enabled higher yield ofextracted fluids from the formation and also reduced the inflow offormation sediments into the well bore. Typically the well casing iscemented into the borehole, and the casing perforated with shots ofgenerally 0.5 inches in diameter over the depth interval to befractured. The formation is hydraulically fractured by injectingfracture fluid into the casing, through the perforations and into theformation. The hydraulic connectivity of the hydraulic fracture orfractures formed in the formation may be poorly connected to the wellbore due to restrictions and damage due to the perforations. Creating ahydraulic fracture in the formation that is well connected hydraulicallyto the well bore will increase the yield from the well, result in lessinflow of formation sediments into the well bore and result in greaterrecovery of the petroleum reserves from the formation.

Turning now to the prior art, hydraulic fracturing of subsurface earthformations to stimulate production of hydrocarbon fluids fromsubterranean formations has been carried out in many parts of the worldfor over fifty years. The earth is hydraulically fractured eitherthrough perforations in a cased well bore or in an isolated section ofan open bore hole. The horizontal and vertical orientation of thehydraulic fracture is controlled by the compressive stress regime in theearth and the fabric of the formation. It is well known in the art ofrock mechanics that a fracture will occur in a plane perpendicular tothe direction of the minimum stress, see U.S. Pat. No. 4,271,696 toWood. At significant depth, one of the horizontal stresses is generallyat a minimum, resulting in a vertical fracture formed by the hydraulicfracturing process. It is also well known in the art that the azimuth ofthe vertical fracture is controlled by the orientation of the minimumhorizontal stress in consolidated sediments and brittle rocks.

At shallow depths, the horizontal stresses could be less or greater thanthe vertical overburden stress. If the horizontal stresses are less thanthe vertical overburden stress, then vertical fractures will beproduced; whereas if the horizontal stresses are greater than thevertical overburden stress, then a horizontal fracture will be formed bythe hydraulic fracturing process.

Hydraulic fracturing generally consists of two types, propped andunpropped fracturing. Unpropped fracturing consists of acid fracturingin carbonate formations and water or low viscosity water slickfracturing for enhanced gas production in tight formations. Proppedfracturing of low permeable rock formations enhances the formationpermeability for ease of extracting petroleum hydrocarbons from theformation. Propped fracturing of high permeable formations is for sandcontrol, i.e. to reduce the inflow of sand into the well bore, byplacing a highly permeable propped fracture in the formation and pumpingfrom the fracture thus reducing the pressure gradients and fluidvelocities due to draw down of fluids from the well bore. Hydraulicfracturing involves the literally breaking or fracturing the rock byinjecting a specialized fluid into the well bore passing throughperforations in the casing to the geological formation at pressuressufficient to initiate and/or extend the fracture in the formation. Thetheory of hydraulic fracturing utilizes linear elasticity and brittlefailure theories to explain and quantify the hydraulic fracturingprocess. Such theories and models are highly developed and generallysufficient for the art of initiating and propagating hydraulic fracturesin brittle materials such as rock, but are totally inadequate in theunderstanding and art of initiating and propagating hydraulic fracturesin ductile materials such as unconsolidated sands and weakly cementedformations.

Hydraulic fracturing has evolved into a highly complex process withspecialized fluids, equipment and monitoring systems. The fluids used inhydraulic fracturing vary depending on the application and can be water,oil, or multi-phased based gels. Aqueous based fracturing fluids consistof a polymeric gelling agent such as solvatable (or hydratable)polysaccharide, e.g. galactomannan gums, glycomannan gums, and cellulosederivatives. The purpose of the hydratable polysaccharides is to thickenthe aqueous solution and thus act as viscosifiers, i.e. increase theviscosity by 100 times or more over the base aqueous solution. Across-linking agent can be added which further increases the viscosityof the solution. The borate ion has been used extensively as across-linking agent for hydrated guar gums and other galactomannans, seeU.S. Pat. No. 3,059,909 to Wise. Other suitable cross-linking agents arechromium, iron, aluminum, and zirconium (see U.S. Pat. No. 3,301,723 toChrisp) and titanium (see U.S. Pat. No. 3,888,312 to Tiner et al). Abreaker is added to the solution to controllably degrade the viscousfracturing fluid. Common breakers are enzymes and catalyzed oxidizerbreaker systems, with weak organic acids sometimes used.

Oil based fracturing fluids are generally based on a gel formed as areaction product of aluminum phosphate ester and a base, typicallysodium aluminate. The reaction of the ester and base creates a solutionthat yields high viscosity in diesels or moderate to high API gravityhydrocarbons. Gelled hydrocarbons are advantageous in water sensitiveoil producing formations to avoid formation damage, that would otherwisebe caused by water based fracturing fluids.

The method of controlling the azimuth of a vertical hydraulic fracturein formations of unconsolidated or weakly cemented soils and sedimentsby slotting the well bore or installing a pre-slotted or weakened casingat a predetermined azimuth has been disclosed. The method disclosed thata vertical hydraulic fracture can be propagated at a pre-determinedazimuth in unconsolidated or weakly cemented sediments and that multipleorientated vertical hydraulic fractures at differing azimuths from asingle well bore can be initiated and propagated for the enhancement ofpetroleum fluid production from the formation. See U.S. Pat. No.6,216,783 to Hocking et al, U.S. Pat. No. 6,443,227 to Hocking et al,U.S. Pat. No. 6,991,037 to Hocking, U.S. patent application Ser. No.11/363,540 and U.S. patent application Ser. No. 11/277,308. The methoddisclosed that a vertical hydraulic fracture can be propagated at apre-determined azimuth in unconsolidated or weakly cemented sedimentsand that multiple orientated vertical hydraulic fractures at differingazimuths from a single well bore can be initiated and propagated for theenhancement of petroleum fluid production from the formation. It is nowknown that unconsolidated or weakly cemented sediments behavesubstantially different from brittle rocks from which most of thehydraulic fracturing experience is founded.

Accordingly, there is a need for a method and apparatus for enhancingthe extraction of hydrocarbons from oil sands by direct heating, steamand/or solvent injection, or a combination thereof and controlling thesubsurface environment, both temperature and pressure to optimize thehydrocarbon extraction in terms of produced rate, efficiency, andproduced product quality, as well as limit water inflow into the processzone.

SUMMARY OF THE INVENTION

The present invention is a method and apparatus for enhanced recovery ofpetroleum fluids from the subsurface by convective heating of the oilsand formation and the heavy oil and bitumen in situ, by either adownhole heater in the well bore or heat supplied to the well bore by aheat transferring fluid from a surface fired heater or surface burner.Multiple propped hydraulic fractures are constructed from the well boreinto the oil sand formation and filled with a highly permeable proppant.The permeable propped fractures and well bore are filled with a diluentand elevated temperatures from the heater set up thermal convectivecells in the diluent forcing heated diluent to flow upward and outwardin the propped fractures and circulating back down and back towards thewell bore heating the oil sands and in situ bitumen on the verticalfaces of the propped fractures. The diluent now mixed with producedproducts from the oil sand re-enters the bottom of the well bore andpasses over the heater element and is reheated to continue to flow inthe convective cell. Thus the heating and diluting of the in placebitumen is predominantly circumferential, i.e. orthogonal to the proppedfracture, diffusion from the propped vertical fracture faces progressingat a nearly uniform rate into the oil sand deposit. To limit upwardgrowth of the process, a non condensing gas can be injected to remain inthe uppermost portions of the propped fractures.

The processes active at the contact of the diluent with the bitumen inthe oil sand are predominantly diffusive, being driven by partialpressure gradients and thermal gradients, resulting in the diffusion ofdiluent components into the bitumen and the conduction of heat from thediluent into the bitumen and oil sand formation. Upon softening of thebitumen, the oil will become mobile and additional smaller convectivecells will developed providing better mixing of the diluent in thepropped fracture and the every expanded zone of mobile oil in the nativeoil sand formation.

The diluent would preferably be an on site diluent, light oil, ornatural gas condensate stream, or a mixture thereof, with its selectedcomposition to provide a primarily liquid phase of the diluent in theprocess zone at the imposed reservoir temperatures and pressures. Thediluent could be derived from synthetic crude if available. The primeuse of the diluent is to transfer by convection, heat from the well boreto the process zone, heat and dilute the produced product to yield amixture that will flow readily at the elevated temperatures through theoil sands and propped fractures back to the well bore. The selectedrange of temperatures and pressures to operate the process will dependon reservoir depth, ambient conditions, quality of the in place heavyoil and bitumen, composition of the diluent, and the presence of nearbywater bodies. The process can be operated at a low temperature range of˜100° C. for a heavy oil rich oil sand deposit and at a moderatetemperature range of ˜150°-180° C. for a bitumen rich oil sand deposit,basically to reduce the bitumen viscosity and thus mobilized the inplace oil. However, the process can be operated a much highertemperatures >270° C. to pyrolysis the in place hydrocarbon in thepresence of hydrogen and/or catalysts. The operating pressure of theprocess may be selected to closely match the ambient reservoirconditions to minimize water inflow into the process zone and the wellbore. However, the process operating conditions may deviate from thispressure in order to maintain the diluent and produced mixture in apredominantly liquid state, i.e. the diluent is to remain in most partsoluble in the produced heavy oil or bitumen at the operating processtemperatures and pressures.

To accelerate the process, forced convection by a pump can assist andtransfer additional heat into the propped fracture convective cells, bypumping the diluent and produced product at greater velocities past theheater and into the propped fractures and mobile zone within the oilsands.

During the heating and diluting process in situ, only a small quantityof the mobile produced product will be extracted from the subsurface inorder to maintain reservoir pressures optimum for the process and tomaintain a high liquid level in the process zone, thus resulting heattransfer occurring at more or less a uniform rate in a circumferentialdirection. Drawing down the pressure for petroleum extraction willresult in gas release from the mixture filling the upper portion of theprocess zone as the liquids are extracted from the formation. Uponproduction of the liquid hydrocarbons the gas in the process zone couldbe produced by sweeping the process zone with another gas, or the gascould be re-pressurized to reservoir conditions to minimize water inflowinto the process zone and the thermal energy in the process zone oilsands allowed to conduct radially into the surrounding cooler oil sandsand thus mobilize additional hydrocarbons (i.e. a heat conductive soak)albeit at a much reduced rate than during the active heating phase ofthe process. Finally the remaining liquid hydrocarbons and gas areproduced from the oil sand formation after some extended heat conductivesoak period.

The prime benefits of the above process are to provide an efficient lowtemperature heating phase to mobilize the hydrocarbon in situ, toproduce a higher grade petroleum product, and to maintain ambientreservoir pressure conditions and thus limit water inflow into theprocess zone. The disadvantage of the process is that only minimalquantities of hydrocarbons are extracted from the subsurface during theactive heating phase of the process since the majority of thehydrocarbons are produced near the end of the process.

Although the present invention contemplates the formation of fractureswhich generally extend laterally away from a vertical or near verticalwell penetrating an earth formation and in a generally vertical plane,those skilled in the art will recognize that the invention may becarried out in earth formations wherein the fractures and the well borescan extend in directions other than vertical.

Therefore, the present invention provides a method and apparatus forenhanced recovery of petroleum fluids from the subsurface by convectiveheating of the oil sand formation and the viscous heavy oil and bitumenin situ, more particularly to a method and apparatus to extract aparticular fraction of the in situ hydrocarbon reserve by controllingthe reservoir temperature and pressure, while also minimizing waterinflow into the heated zone and well bore resulting in increasedproduction of petroleum fluids from the subsurface formation.

Other objects, features and advantages of the present invention willbecome apparent upon reviewing the following description of thepreferred embodiments of the invention, when taken in conjunction withthe drawings and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a horizontal cross-section view of a well casing having dualfracture winged initiation sections prior to initiation of multipleazimuth controlled vertical fractures.

FIG. 2 is a cross-sectional side elevation view of a well casing havingdual fracture winged initiation sections prior to initiation of multipleazimuth controlled vertical fractures.

FIG. 3 is an isometric view of a well casing having dual proppedfractures with downhole heater and convection fluid flow shown in thesubsurface.

FIG. 4 is a horizontal cross-sectional side elevation view of a wellcasing and propped fracture with downhole heater and convective fluidflow shown in the subsurface.

FIG. 5 is a horizontal cross-section view of a well casing havingmultiple fracture dual winged initiation sections after initiation ofall four controlled vertical fractures.

FIG. 6 is an isometric view of a well casing having four proppedfractures with downhole heater and convection fluid flow shown in thesubsurface.

FIG. 7 is an isometric view of a well casing having dual multi-stagepropped fractures with downhole heater and convection fluid flow shownin the subsurface.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT

Several embodiments of the present invention are described below andillustrated in the accompanying drawings. The present invention involvesa method and apparatus for enhanced recovery of petroleum fluids fromthe subsurface by convective heating of the oil sand formation and theheavy oil and bitumen in situ, by either a downhole heater in the wellbore or heat supplied to the well bore by a heat transferring fluid froma surface fired heater or surface burner. Multiple propped hydraulicfractures are constructed from the well bore into the oil sand formationand filled with a highly permeable proppant. The permeable proppedfractures and well bore are filled with a diluent, the heater and pumpactivated with forced thermal convective flow forcing the heated diluentto flow upward and outward in the propped fractures and circulating backdown and back towards the well bore heating the oil sands and in situbitumen on the vertical faces of the propped fractures. The diluent nowmixed with produced products from the oil sand re-enters the bottom ofthe well bore and passes over the heater element and is reheated tocontinue to flow in the convective cell. Thus the heating and dilutingof the in place bitumen is predominantly circumferentially, i.e.orthogonal to the propped fracture, diffusion from the propped verticalfracture faces progressing at a nearly uniform rate into the oil sanddeposit. The heated low viscosity oil is produced through the well boreat the completion of the active heating phase of the process.

Referring to the drawings, in which like numerals indicate likeelements, FIGS. 1, 2, and 3 illustrate the initial setup of the methodand apparatus for forming an in situ forced convective heating system ofthe oil sand deposit and for the extraction of the processedhydrocarbons. Conventional bore hole 5 is completed by wash rotary orcable tool methods into the formation 8 to a predetermined depth 7 belowthe ground surface 6. Injection casing 1 is installed to thepredetermined depth 7, and the installation is completed by placement ofa grout 4 which completely fills the annular space between the outsidethe injection casing 1 and the bore hole 5. Injection casing 1 consistsof four initiation sections 21, 22, 23, and 24 to produce two fracturesone orientated along plane 2, 2′ and one orientated along plane 3, 3′.Injection casing 1 must be constructed from a material that canwithstand the pressures that the fracture fluid exerts upon the interiorof the injection casing 1 during the pressurization of the fracturefluid. The grout 4 can be any conventional material used in steaminjection casing cementation systems that preserves the spacing betweenthe exterior of the injection casing 1 and the bore hole 5 throughoutthe fracturing procedure, preferably a non-shrink or low shrink cementbased grout that can withstand high temperature and differentialstrains.

The outer surface of the injection casing 1 should be roughened ormanufactured such that the grout 4 bonds to the injection casing 1 witha minimum strength equal to the down hole pressure required to initiatethe controlled vertical fracture. The bond strength of the grout 4 tothe outside surface of the casing 1 prevents the pressurized fracturefluid from short circuiting along the casing-to-grout interface up tothe ground surface 6.

Referring to FIGS. 1, 2, and 3, the injection casing 1 comprises twofracture dual winged initiation sections 21, 22, 23, and 24 installed ata predetermined depth 7 within the bore hole 5. The winged initiationsections 21, 22, 23, and 24 can be constructed from the same material asthe injection casing 1. The position below ground surface of the wingedinitiation sections 21, 22, 23, and 24 will depend on the required insitu geometry of the induced hydraulic fracture and the reservoirformation properties and recoverable reserves.

The hydraulic fractures will be initiated and propagated by an oil basedfracturing fluid consisting of a gel formed as a reaction product ofaluminum phosphate ester and a base, typically sodium aluminate. Thereaction of the ester and base creates a solution that yields highviscosity in diesels or moderate to high API gravity hydrocarbons.Gelled hydrocarbons are advantageous in water sensitive oil producingformations to avoid formation damage, that would otherwise be caused bywater based fracturing fluids. The oil based gel provides the addedadvantage of placing the required diluent within the propped fracture,without the inherent problems of injecting a diluent into a watersaturated proppant fracture if water based fracturing fluids were used.

The pumping rate of the fracturing fluid and the viscosity of thefracturing fluids needs to be controlled to initiate and propagate thefracture in a controlled manner in weakly cemented sediments such as oilsands. The dilation of the casing and grout imposes a dilation of theformation that generates an unloading zone in the oil sand, and suchdilation of the formation reduces the pore pressure in the formation infront of the fracturing tip. The variables of interest are v thevelocity of the fracturing fluid in the throat of the fracture, i.e. thefracture propagation rate, w the width of the fracture at its throat,being the casing dilation at fracture initiation, and μ the viscosity ofthe fracturing fluid at the shear rate in the fracture throat. TheReynolds number is Re=ρvw/μ. To ensure a repeatable single orientatedhydraulic fracture is formed, the formation needs to be dilatedorthogonal to the intended fracture plane, the fracturing fluid pumpingrate needs to be limited so that the Re is less than 1.0 during fractureinitiation and less than 2.5 during fracture propagation. Also if thefracturing fluid can flow into the dilated zone in the formation aheadof the fracture and negate the induce pore pressure from formationdilation, then the fracture will not propagate along the intendedazimuth. In order to ensure that the fracturing fluid does not negatethe pore pressure gradients in front of the fracture tip, its viscosityat fracturing shear rates within the fracture throat of ˜1-20 sec—1needs to be greater than 100 centipoise.

The fracture fluid forms a highly permeable hydraulic fracture byplacing a proppant in the fracture to create a highly permeablefracture. Such proppants are typically clean sand for large massivehydraulic fracture installations or specialized manufactured particles(generally resin coated sand or ceramic in composition), which aredesigned also to limit flow back of the proppant from the fracture intothe well bore. The fracture fluid-gel-proppant mixture is injected intothe formation and carries the proppant to the extremes of the fracture.Upon propagation of the fracture to the required lateral 31 and verticalextent 32 (FIG. 3), the predetermined fracture thickness may need to beincreased by utilizing the process of tip screen out or by re-fracturingthe already induced fractures. The tip screen out process involvesmodifying the proppant loading and/or fracture fluid properties toachieve a proppant bridge at the fracture tip. The fracture fluid isfurther injected after tip screen out, but rather then extending thefracture laterally or vertically, the injected fluid widens, i.e.thickens, and fills the fracture from the fracture tip back to the wellbore.

Referring to FIG. 3, the casing 1 is washed clean of fracturing fluidsand screens 25 and 26 are present in the casing as a bottom screen 25and a top screen 26 for hydraulic connection from the casing well bore 1to the propped fractures 30. A downhole electric heater 17 is placedinside the casing, with a downhole pump 18, connected to a power andinstrumentation cable 27, with downhole packers 16 to isolate the topscreen interval from the remaining sections of the well bore, piping 27,and downhole valve 19. The heater 17 and pump 18 are energized throughelectric power provided from the surface through cable 27. The pump andthermal buoyancy effects forces the diluent fluid to flow 13 past theheater into 14 the pump 18 and up 15 the tubing 27 and out of the topscreen 26. The downhole valve 19 in the closed position enables thepumped hot fluid to flow through the top screen 26 into the fracture andoil sand formation as flow vectors 10, 11, and 12 illustrating theconvection cell formation due to the pumped hot fluid. The surfacecontrolled downhole valve 19 in the open position enables the pump fluidto flow only up the tubing 9 and not into the top screen 26. The fluiddiluent is cooled by the oil sands 8 adjacent to the propped fractures30 as it flows from 10 to 11 to 12, and enters the well bore through thebottom screen 25 to be convectively moved 13 up past the heater 17 for areturn to the forced convective re-circulation cell.

Referring to FIGS. 3 and 4, the hot diluent flows in a re-circulationforce convective cell as shown by vectors 10, 11, and 12 in the proppedfracture 30 with proppant shown 34 and mobilized oil sand zone 35adjacent to the propped fractures 34. The mobilized oil sand zoneextends into the bitumen oil sands 36 by diffusive processes 33 due topartial pressure and temperature gradients. The mixture of diluent andproduced bitumen results in a modified hydrocarbon that flows from thebitumen 36 into the mobilized oil sand zone 35 and the propped fracture34 to flow eventually as 12 into the lower screen 25 of the well bore.The process zone includes the propped hydraulic fractures 30, the mobilezone 35 in the oil sands of the formation, and the fluid containedtherein. In some cases, the well bore casing 1 may be considered part ofthe process zone when a part of the process for recovering hydrocarbonsfrom the formation is carried out in the well casing.

The mobilized oil sand zone 35 grows circumferentially 33, i.e.orthogonal to the propped fractures 30, and becomes larger with timeuntil eventually the bitumen within the lateral 31 and vertical 32extent of the propped fracture system is completely mobilized by theelevated temperature and diffused diluent. As the mobilized oil sandregion 35 grows the diluent fluid 12 entering the lower screen 26 of thewell bore becomes a mixture of mobilized oil from the bitumen and theoriginal diluent. It may be necessary to dilute this mixture from timeto time with additional diluent to yield the required viscosity and heattransfer properties of the heated fluid in the re-circulation cell. Upongrowth of the mobilized oil sand zone to the lateral 31 and vertical 32extents of the propped fractures 30, the valve 19 will be open and theliquid hydrocarbons produced up the tubing 9 to the surface.

As the pressure is lowered during hydrocarbon production to the surface,gases from the diluent and bitumen mixture will fill the mobilized oilsand region 35 and the propped fractures 34. Re-pressurizing these gasesback to ambient reservoir pressures will minimize water inflow into theheated region and an extended heat conduction soak can provideadditional mobilized hydrocarbons from the oil sands with out additionalheat required. Alternatively, the process zone can be injected with avaporized hydrocarbon solvent, such as ethane, propane, or butane andmixed with a diluent gas, such as methane, nitrogen, and carbon dioxide.The solvent will contact the in situ bitumen at the edge of the processzone, diffusive into and soften the bitumen, so that it flows by gravityto the well bore. Dissolved solvent and product hydrocarbon are producedand further solvent and diluent gas injected into the process zone. Theelevated temperature of the process zone will significantly acceleratethe diffusion process of the solvent diffusing into the bitumen comparedto ambient reservoir conditions. The solvent and diluent gas will beinjected at near reservoir pressures to minimize water inflow into theprocess zone. The solvent vapor in the injection gas is maintainedsaturated at or near its dew point at the process operating temperaturesand pressures.

During the active heating phase of the process, the reservoirtemperatures and pressures and composition of the produced fluid will becontrolled to optimize the process as regards the quality andcomposition of the produced product, the heat transfer, and diluentproperties of the produced mixture, and to minimize water inflow intothe process zone and well bore.

Another embodiment of the present invention is shown on FIGS. 5 and 6,consisting of an injection casing 38 inserted in a bore hole 39 andgrouted in place by a grout 40. The injection casing 38 consists ofeight symmetrical fracture initiation sections 41, 42, 43, 44, 45, 46,47, and 48 to install a total of four hydraulic fractures on thedifferent azimuth planes 31, 31′, 32, 32′, 33, 33′, 34, and 34′. Theprocess results in four hydraulic fractures installed from a single wellbore at different azimuths as shown on FIG. 6. The casing 1 is washedclean of fracturing fluids and screens 25 and 26 are present in thecasing as a bottom screen 25 and a top screen 26 for hydraulicconnection of the well bore 10 to the propped fractures 30. A downholeelectric heater 17 is placed inside the casing, with a downhole pump 18,connected to a power and instrumentation cable 27, with downhole packers16 to isolate the top screen interval from the remaining sections of thewell bore, piping 27, and downhole valve 19. The heater 17 and pump 18are energized through electric power provided from the surface throughcable 27. The pump and thermal buoyancy effects force the diluent fluidto flow 13 past the heater into 14 the pump 18 and up 15 the tubing 27and out of the top screen 26. The downhole valve 19 in the closedposition enables the pumped hot fluid to flow through the top screen 26into the fracture and oil sand formation as flow vectors 10, 11, and 12illustrating the convection cell formation due to the pumped hot fluid.The fluid diluent is cooled by the oil sands 8 adjacent to the proppedfractures 30 as it flows from 10 to 11 to 12, and enters the well borethrough the bottom screen 25 to be convectively moved 13 up past theheater 17 for a return to the forced convective re-circulation cell.Following the active heater phase of the process, the mobilizedhydrocarbons are produced from the well bore and heated zone throughopening the downhole valve 19 and transported by tubing 9 to thesurface.

Another embodiment of the present invention is shown on FIG. 7, similarto FIG. 3 except that the hydraulic fractures are constructed by amulti-stage process with various proppant materials of differingpermeability. Multi-stage fracturing involves first injecting a proppantmaterial 50 to form a hydraulic fracture 30. Prior to creation of thefull fracture extent, a different proppant material 51 is injected intothe fracture over a reduced central section of the well bore 53 tocreate an area of the hydraulic fracture loaded with the differentproppant material 51. Similarly, the multi-stage fracturing couldconsist of a third stage by injecting a third different proppantmaterial 52. By the appropriate selection of proppants with differingpermeability, the circulation of the diluent and mobilized oil in theformed fracture can be extended laterally a greater distance compared toa hydraulic fracture filled with a uniform permeable proppant, as shownearlier in FIG. 3. The proppant materials are selected so that theproppant material 50 has the highest proppant permeability, withproppant material 51 being lower, and with proppant material 52 havingthe lowest proppant permeability. The different permeability of theproppant materials thus optimizes the lateral extent of the fluidsflowing within the hydraulic fractures and controls the geometry andpropagation rate of the convective heat to the oil sand formation. Thepermeability of the proppant materials will typically range from 1 to100 Darcy for the proppant material 50 in the fracture zone, i.e.generally being at least 10 times greater than the oil sand formationpermeability. The proppant material 51 in fracture zone is selected tobe lower than the proppant material 50 in the fracture zone by at leasta factor of 2, and proppant material 52 in the fracture zone close tothe well bore casing 1 is selected to be in the milli-Darcy range thuslimiting fluid flow in the fracture zone containing the proppantmaterial 52.

Finally, it will be understood that the preferred embodiment has beendisclosed by way of example, and that other modifications may occur tothose skilled in the art without departing from the scope and spirit ofthe appended claims.

1. A method for in situ recovery of hydrocarbons from a hydrocarboncontaining formation, comprising: a. drilling a bore hole in theformation to a predetermined depth to define a well bore with a casing;b. installing one or more vertical hydraulic fractures from the borehole to create a process zone by injecting a fracture fluid into thecasing, wherein the hydraulic fractures contain a proppant and adiluent; c. providing heat from a heat source to raise the temperaturein a section of the bore hole containing the diluent; d. circulating thediluent in the hydraulic fractures and the formation; and e. recoveringa mixture of diluent and hydrocarbons from the formation.
 2. The methodof claim 1, wherein the heat is provided by a downhole heater.
 3. Themethod of claim 2, wherein the heat is provided by a downhole electricheater.
 4. The method of claim 2, wherein the heat is provided by adownhole flameless distributed combustor.
 5. The method of claim 1,wherein the heat is provided by a heat transfer fluid by tubing from asurface fired heater or burner.
 6. The method of claim 1, wherein adownhole pump provides forced convective circulation of the diluent andhydrocarbons mixture.
 7. The method of claim 1, wherein the temperaturein part of the formation is in the order of 100° C. to causehydrocarbons comprising heavy oil to flow under gravity to the wellbore.
 8. The method of claim 1, wherein the temperature in part of theformation is in the range of 150° to 200° C. to cause hydrocarbonscomprising bitumen to flow under gravity to the well bore.
 9. The methodof claim 1, wherein the temperature in part of the formation is in apyrolysis temperature regime of greater than 250° C.
 10. The method ofclaim 1, further comprising controlling the temperature and pressure inthe majority of the part of the process zone, wherein the temperature iscontrolled as a function of pressure, or the pressure is controlled as afunction of temperature.
 11. The method of claim 1, wherein the diluentand hydrocarbon mixture is predominantly in a liquid phase throughoutthe process zone.
 12. The method of claim 1, wherein the pressure in themajority of the part of the process zone is at ambient reservoirpressure.
 13. The method of claim 1, wherein the hydraulic fractures arefilled with proppants of differing permeability.
 14. The method of claim1, wherein the formation includes a mobile zone and wherein circulatingthe diluent causes the heat to transfer predominantly by convection inthe mobile zone and to transfer predominantly from the mobile zone tothe formation substantially by conduction.
 15. The method of claim 1,wherein the method further includes injecting a hydrogenising gas intothe well casing and thus into the fluids in the process zone to promotehydrogenation and thermal cracking of at least a portion of thehydrocarbons in the process zone.
 16. The method of claim 15, whereinthe hydrogenising gas consists of one of the group of H₂ and CO or amixture thereof.
 17. The method of claim 15, wherein the method furtherincludes catalyzing the hydrogenation and thermal cracking of at least aportion of the hydrocarbons in the process zone.
 18. The method of claim17, wherein a metal-containing catalyst is used to catalyze thehydrogenation and thermal cracking reactions.
 19. The method of claim17, wherein the catalyst is contained in a canister in the well casing.20. The method of claim 1, wherein the proppant in the hydraulicfractures contains the catalyst for the hydrogenation and thermalcracking reactions.
 21. The method of claim 1, wherein the diluent is alight oil, a pipeline diluent, natural condensate stream, or a fractionof a synthetic crude or a mixture thereof.
 22. The method of claim 1,wherein additional quantities of diluent are injected over time into thewell bore to modify the composition of the diluent and hydrocarbonsmixture within the process zone.
 23. The method of claim 1, wherein alight non-condensing low hydrocarbon solubility gas is injected to fillthe uppermost portion of the hydraulic fractures to inhibit upwardgrowth of the process zone.
 24. The method of claim 1, wherein the heatsource is removed and the hydrocarbons are produced from the formationand a hydrocarbon solvent is injected into the process zone in avaporized state.
 25. The method of claim 24, wherein the solvent is oneof a group of ethane, propane, butane or a mixture thereof.
 26. Themethod of claim 24, wherein the solvent is mixed with a diluent gas. 27.The method of claim 26, wherein the diluent gas is non-condensable underprocess conditions in the process zone.
 28. The method of claim 26,wherein the non-condensable diluent gas has a lower solubility in thehydrocarbons in the formation than the saturated hydrocarbon solvent.29. The method of claim 26, wherein the diluent gas is one of a group ofmethane, nitrogen, carbon dioxide, natural gas, or a mixture thereof.30. The method of claim 1, wherein at least two vertical fractures areinstalled from the bore hole at approximately orthogonal directions. 31.The method of claim 1, wherein at least three vertical fractures areinstalled from the bore hole.
 32. The method of claim 1, wherein atleast four vertical fractures are installed from the bore hole.
 33. Ahydrocarbon production well in a formation of unconsolidated and weaklycemented sediments, comprising: a. a bore hole in the formation to apredetermined depth; b. an injection casing grouted in the bore hole atthe predetermined depth, the injection casing including multipleinitiation sections separated by a weakening line and multiple passageswithin the initiation sections and communicating across the weakeningline for the introduction of a fracture fluid to dilate the casing andseparate the initiation sections along the weakening line; c. a sourcefor delivering the fracture fluid into the injection casing withsufficient fracturing pressure to dilate the injection casing and theformation and initiate a vertical fracture at an azimuth orthogonal tothe direction of dilation to create a process zone within the formation,for controlling the propagation rate of each individual opposing wing ofthe hydraulic fracture, and for controlling the flow rate of thefracture fluid and its viscosity so that the Reynolds Number Re is lessthan 1 at fracture initiation and less than 2.5 during fracturepropagation and the fracture fluid viscosity is greater than 100centipoise at the fracture tip; d. a source for delivering a diluent inthe casing above the elevation of the highest hydraulic fracture; e. aheat source positioned within the casing and in contact with the diluentfor heating the diluent; f. circulating the diluent in a process zoneincluding the hydraulic fractures and the formation; and g. recovering amixture of diluent and hydrocarbons from the formation through thecasing.
 34. The well of claim 33, wherein the heat source is a downholeheater.
 35. The well of claim 33, wherein the heat source is a downholeelectric heater.
 36. The well of claim 33, wherein the heat source is adownhole flameless distributed combustor.
 37. The well of claim 33,wherein the heat source is a surface fired heater or burner and tubingcontaining a heat transfer fluid.
 38. The well of claim 33, wherein adownhole pump provides forced convective flow of the diluent andhydrocarbons mixture.
 39. The well of claim 33, wherein the heat sourceproduces a temperature in part of the formation that is in the order of100° C. for the hydrocarbons comprising heavy oil thereby causing theheavy oil to flow under gravity to the well bore.
 40. The well of claim33, wherein the heat source produces a temperature in part of theformation that is in the range of 150° to 200° C. for the hydrocarbonscomprising bitumen to cause the bitumen to flow under gravity to thewell bore.
 41. The well of claim 33, wherein the heat source produces atemperature in part of the formation that is in a pyrolysis temperatureregime of greater than 250° C.
 42. The well of claim 33, furthercomprising a temperature and pressure regulator that controls thetemperature and pressure in a majority of a part of the process zone,wherein the temperature is controlled as a function of pressure, or thepressure is controlled as a function of temperature.
 43. The well ofclaim 33, wherein the diluent and hydrocarbons mixture is predominantlyin the liquid phase throughout the process zone.
 44. The well of claim33, wherein the pressure in the majority of the part of the process zoneis at ambient reservoir pressure.
 45. The well of claim 33, wherein thehydraulic fractures are filled with proppants of differing permeability.46. The well of claim 33, wherein the formation includes a mobile zoneand wherein heat produced by the heat source transfers predominantly byconvection in the mobile zone and transfer predominately from the mobilezone to the formation by conduction.
 47. The well of claim 33, whereinthe well includes means for injecting a hydrogenising gas into the wellcasing and thus into the fluids in the process zone to promotehydrogenation and thermal cracking of at least a portion of thehydrocarbons in the process zone.
 48. The well of claim 33, wherein thehydrogenising gas consists of one of the group of H₂ and CO or a mixturethereof.
 49. The well of claim 48, wherein the well includes means forcatalyzing the hydrogenation and thermal cracking of at least a portionof the hydrocarbons in the process zone.
 50. The well of claim 49,wherein a metal-containing catalyst is used to catalyze thehydrogenation and thermal cracking reactions.
 51. The well of claim 50,wherein well casing includes a canister containing the catalyst for thehydrogenation and thermal cracking reactions.
 52. The well of claim 33,wherein the proppant in the hydraulic fractures contains the catalystfor the hydrogenation and thermal cracking reactions.
 53. The well ofclaim 33, wherein the diluent is a light oil, pipeline diluent, naturalcondensate stream, or fraction of a synthetic crude or a mixturethereof.
 54. The well of claim 33, wherein the well includes means forinjecting additional quantities of diluent over time into the wellcasing to modify the composition of the diluent and hydrocarbons mixturewithin the process zone.
 55. The well of claim 33, wherein the wellincludes means for injecting a light non-condensing low hydrocarbonsolubility gas to fill the uppermost portion of the hydraulic fracturesto inhibit upward growth of the process zone.
 56. The well of claim 33,wherein the heat source is removed and the hydrocarbons are producedfrom the formation and a hydrocarbon solvent is injected into theprocess zone in a vaporized state.
 57. The well of claim 56, wherein thesolvent is one of a group of ethane, propane, butane, or a mixturethereof.
 58. The well of claim 56, wherein the solvent is mixed with adiluent gas.
 59. The well of claim 56, wherein the diluent gas isnon-condensable under process conditions in the process zone.
 60. Thewell of claim 59, wherein the non-condensable diluent gas has a lowersolubility in the hydrocarbons in the formation than the saturatedhydrocarbon solvent.
 61. The well of claim 60, wherein the diluent gasis one of a group of methane, nitrogen, carbon dioxide, natural gas, ora mixture thereof.
 62. The well of claim 33, wherein the well includesat least two vertical fractures installed from the bore hole atapproximately orthogonal directions.
 63. The well of claim 33, whereinthe well includes at least three vertical fractures installed from thebore hole.
 64. The well of claim 33, wherein the well includes at leastfour vertical fractures installed from the bore hole.